1. Field of the Invention
This invention relates to the hydraulic fracturing of subterranean formations surrounding oil wells, gas wells and similar boreholes. In one aspect it relates to a fracturing method employing an improved fracturing fluid.
2. Description of the Prior Art
Hydraulic fracturing is a widely used stimulation technique for increasing the production of crude oil and natural gas from wells in low permeability formations. The method normally involves the injection of a fracturing fluid into a well at a rate and pressure sufficient to propagate a fracture adjacent the well. Propping agent particles suspended in the fracturing fluid maintain the fracture in a propped condition when the applied pressure is relieved.
A fracturing fluid should have a high viscosity when injected into the well. High viscosity fluids tend to generate wider and longer fractures and are capable of maintaining large, high density propping agent particles in suspension. There are two basic types of high viscosity fracturing fluids--emulsions and fluids containing polymers. Although these fluids give good fracturing results they do have certain disadvantages. One problem is that they are difficult to recover from the formation. Removal of the fracturing fluid, known as well clean-up, is usually accomplished by the flushing action of the formation fluid flowing in the well. However, this technique is normally not adequate when a high viscosity fracturing fluid is used, especially in tight formations or low pressure formations.
Emulsion fracturing fluids get their high viscosity from the dispersion of a major proportion of an oil internal phase in a minor proportion of an external aqueous phase. The emulsion must be stabilized by a surfactant. To reduce the viscosity of the emulsion to permit easy removal of the fracturing fluid it is necessary to break the emulsion into a water-in-oil invert or into its component phases. The emulsion is usually broken by eliminating the stabilizing effect of the surfactant. This is normally accomplished either by adsorption of surfactant on the formation walls or by the addition of a demulsifying agent. Normally, only cationic surfactants are susceptible to adsorption on to formation materials because of their affinity for sand surfaces. If, on the other hand, a demulsifier is used, the demulsifier and surfactant must be carefully matched so that the emulsion begins to break only after fracturing is completed. Even with suitably matched demulsifiers and surfactants, it is not easy to accurately time the breaking of the emulsion and there is always the danger that demulsification will either take place prematurely or will be delayed for an unacceptably long period of time.
The second category of high viscosity fluids is the polymerically thickened fluid. A polymer, such as guar gum, is used in the fluid as a thickening agent to greatly increase its viscosity. The polymer also tends to reduce pumping friction losses and certain polymers (e.g., guar gum) also impart fluid loss control.
Polymerically thickened fluids, however, also present removal problems once the fracturing operation is completed. Consequently, polymer degradation systems must be devised to break down the polymer in order to reduce the viscosity of the fluid. The polymer can be destroyed by enzymatic action, acidification, oxidation or hydrolysis. For example, guar gum is normally broken down by cellulose enzymes whereas synthetic cellulose derivatives, which are only slightly susceptible to enzymes, are usually oxidized. The selection of a suitable method for destroying the polymer is not an easy task because the activity of oxidizers and enzymes is often sensitive to pH, salinity, and temperature. Buffers frequently must be used to improve the effectiveness of the oxidizer enzyme. At formation temperatures in excess of 165.degree.F, both enzymes and oxidizers lose much of their effectiveness and hydrolytic polymer degradation is necessary. Improper selection of a suitable method for destroying the polymer will result in insufficent viscosity reduction.
The degraded polymer, however, creates additional problems. For example, degraded guar gum is not completely water soluble and frequently leaves a residue in the formation which can greatly reduce fracture permeability. Thus, the increased fracture conductivity obtained with the polymer fluid can be significantly offset by permeability reductions caused by guar gum residues. (See SPE Paper 5114 entitled "Effect of Fracturing Fluids on Fracture Conductivity" by C. E. Cooke, Jr., which analyzes the problem of polymer residues.)
Another problem with polymers is that they are sensitive to the formation environment. Contaminants found in field grade waters which alter the pH or salinity of the fracturing fluid are responsible for substantial variations in polymer fluid viscosities. A detailed analysis of the substantial effect of pH and ionic concentration on polymer viscosity can be found in SPE Paper 5005 entitled "Use of Guar Gum and Synthetic Cellulose in Oilfield Stimulation Fluids" by R. W. Anderson and J. W. Baker. Once again, buffers must be used to counteract interference by contaminated ions, thus necessitating an analysis of field grade waters to determine the type of ions present and their concentration.
A more recent development is a fracturing fluid consisting of an oil-in-water emulsion containing a polymer. As described by O. M. Kiel in U.S. Pat. No. 3,710,865 and by Sinclair et al in J. Pet. Tech (July, 1974), pp. 731-738, the preferred composition of this fracturing fluid is an oil-in-water emulsion comprising from 60 to 75 volume percent of an internal oil phase and an aqueous phase containing about 0.5 weight percent of a cationic surfactant and about 0.5 weight percent of a polymer.
Generally, oil-in-water emulsions containing an oil phase concentration of less than 75 volume percent do not exhibit sufficient viscosity to be suitable as a fracturing fluid. The addition of the polymer, however, gives the emulsion the desired viscosity. Furthermore, less polymer is needed than with other types of polymer fluids such as gelled waters and gelled acids.
Although a good fracturing fluid, the polymer emulsion is especially difficult to remove from the formation because both the polymer and the emulsion significantly contribute to the high viscosity of the fluid. Consequently, mechanisms are needed to reduce the viscosity contribution of both. The polymer emulsion is usually made to convert to a low viscosity fluid by a combined demulsification and polymer degradation system. The breaker system must permit completion of the fracturing treatment before acting and then must act quick enough to minimize recovery time. Related polymer problems such as degradation residues and ionic sensitivity are also present when the polymer emulsion is used.